Typical oil reservoir formations are made up of rock containing tiny, interconnected pore spaces which are saturated with oil, water, and gas. Knowledge of the concentrations of these fluids in the formation is critical for the efficient production of the oil. When the formation is first drilled, it is necessary to know the original oil saturation in order to plan the exploitation of the field. Later in the life of the field, the amount of oil remaining in the formation will often dictate the most efficient secondary and tertiary recovery operations. A particular need exists to determine the resident oil saturation of a watered-out formation following waterflooding.
Several methods are currently used to determine fluid saturations of a formation. One technique involves coring, i.e., direct sampling of the formation rock and fluids wherein a small portion of rock saturated with fluids is removed and brought to the surface where its fluid content can be analyzed. Coring, however, is susceptible to several shortcomings. First, the small sample may not be representative of the formation as a whole since it only investigates the immediate vicinity of the wellbore. Second, the coring process itself may change the fluid saturations of the samples. Finally, coring can usually only be done in newly drilled wells.
Another method of determining fluid saturations involves logging techniques. This method, too, suffers from the shortcoming of investigating a limited area which is in the immediate vicinity of the wellbore. In addition, logging techniques are often unable to differentiate between properties of the rock and those of its fluids.
Another approach involves material balance calculations based on production history. However, this approach is susceptible to error since it requires a knowledge of the initial fluid saturation of the formation by some other independent means.
More modern methods for determining fluid saturations involve the injection and production of tracers. The techniques are based on chromatographic theory. Typically, two tracers having different partition coefficients are used. The tracers are chromatographically retarded to different extents as they pass through the formation. The degree to which the two tracers are differentially retarded can be used to determine the formation fluid saturations. Tritiated water and water soluble forms of cesium and cobalt isotopes have gained wide acceptance as reliable water tracers for oil reservoir and groundwater studies.
Most tracer techniques for the determination of fluid saturations involve using a single well. A fundamental problem with single well testing is that only a very limited portion of the formation, the area immediately surrounding the wellbore, is investigated. Apart from this fundamental problem, single well testing which attempts to take advantage of chromatographic principles also suffers from an additional shortcoming--the "mirror image" effect. The mirror image effect occurs where two or more tracers having different partition coefficients are injected into a formation. The tracers will separate as they are injected into the formation, and the degree of separation will be a function of the oil saturation. However, when the tracers are withdrawn from the formation by means of the same well, the separation will disappear. In other words, when the tracers move away from the well, one tracer moves faster than the other due to the difference in partition coefficients and the residual oil saturation. When the well was placed on production, the faster moving tracer again moves further than the other and the two tracers arrive at the wellbore at approximately the same time.
Several schemes have been devised to avoid this problem. In one technique, the well is shut in for an extended period of time after the injection of the tracer. This allows the tracers to drift, i.e., to move in the formation under the influence of forces unrelated to the injection or withdrawal of fluids at the well. When the well is put on production, the tracers are somewhat separated and a determination of fluid saturations becomes more feasible. The problem with this technique is that it is difficult to determine the time necessary for the tracers to drift. Furthermore, extended residence time in the formation creates other problems, such as gravitational separation of the tracers.
Another way of avoiding the "mirror image" effect is to inject a non-reactive tracer along with a tracer precursor. The injection is followed by a shut-in period during which the precursor is allowed to react to form a tracer. The precursor and corresponding tracer have different partitioning coefficients. During the injection phase, the precursor and non-reactive tracer move away from the well at certain velocities determined by their partitioning coefficients. During the production phase, the non-reactive tracer moves back toward the wellbore at the same rate, but the newly formed tracer, because it has a different partitioning coefficient from that of its precursor, moves at a rate different from that of its precursor. The result is a separation at the wellbore of the two tracers. The problem with this method is that it depends for its success on chemical reactions which are influenced by various factors, such as formation temperature.
The mirror image problem can be completely circumvented by injecting a carrier fluid containing at least two non-reactive tracers having different partition coefficients between the fluid phases into one location in the formation and producing from another. Typically, one well is used to inject the carrier fluid bearing the tracers while another well is used to produce formation fluids. Because different injection and production locations are used, it is unnecessary to rely on fluid drift for the separation of the tracers. Nor is it necessary to use tracer precursors and rely on chemical reactions to produce tracers with different partitioning coefficients. Instead, non-reactive tracers can be used which are chromatographically separated as they pass through the formation and this chromatographic separation is a function of the saturation of the immobile phase.
The basic idea of chromatographic separation was disclosed by Dr. Claude Cooke in U.S. Pat. No. 3,590,923. Cooke injected fluid containing at least two tracers of different partition coefficients. The tracers were chromatographically retarded in their passage through the formation to different extents. The breakthrough of the tracers was detected in another location, and inferences were drawn about the relative proportion of formation fluids.
While the Cooke method was superior to any of those previously used, it suffered from a number of serious drawbacks. First, little guidance was given on the selection of appropriate tracers. Second, the Cooke method used only tracer breakthrough quantities to calculate residual oil saturation. Because of dispersion, stratification, streamline effects and the detection properties of various tracers, it was usually difficult to determine the precise time of breakthrough with great accuracy. Even when breakthrough was determined with considerable accuracy, the effect of using only the breakthrough was that only the residual oil saturation of the most permeable layer was determined. The saturation of other layers in the formation was not determined by this technique. Thus, there still exists a need in the industry for a method to accurately determine the residual oil saturation of a formation, especially a watered-out reservoir.